1. Field of the Invention
This invention relates to a method for use in oilfield and pipeline operations to monitor and control mineral scale precipitation from formation fluids. This invention particularly relates to a method for monitoring and controlling the deposition of mineral scale that is originating from formation fluids contained in wellbores, pipelines, and related equipment.
2. Background of the Art
Petroleum fluids primarily consist of oil and water and are herein referred to as formation fluids. A formation fluid may also contain oil and water insoluble compounds such as clay, silica, waxes, and asphaltenes, which exist as colloidal suspensions.
In addition to the already listed components, formation fluids can also include inorganic components which can precipitate to form mineral scales. The process of mineral scale precipitation is known as scaling. Of primary concern to this invention are mineral scales and scaling. The most common scale forming ions are calcium and barium, but sodium, carbonate, bicarbonate, chloride, sulfate, and strontium are also recognized as scaling species. The most common speciation of these combined scaling ions are: calcium carbonate (CaCO3), calcium sulfate (CaSO4), barium sulfate (BaSO4), and strontium sulfate (SrSO4). In addition, there are less common scale species, such as calcium fluoride (CaF2), iron sulfide (FexSx+1), zinc sulfide (ZnS), lead sulfide (PbS) and sodium chloride (NaCl).
Scale precipitation is primarily affected by commingling of incompatible produced waters and/or changes in physical properties intrinsic to the well system such as, temperature, pressure, fluid turbulence, fluid flow rate, and pH. Specifically, well equipment in positions where incompatible water commingles and/or changes in these intrinsic physical properties occur is particularly vulnerable to scale precipitation. It has also been recognized that well equipment and topside equipment downstream of these sites are also susceptible to scale precipitation in the well system. Any mineral scale sticking to the well system surfaces may narrow pipes, and clog wellbore perforations, various flow valves, and other wellsite and downhole equipment, which results in wellsite equipment failures. It may also slow down, reduce or even totally prevent the flow of formation fluid into the wellbore and/or out of the wellhead. These effects also extend to crude oil storage facilities which incur maintenance or capacity problems when mineral scale precipitations remain undetected for extended periods of time.
As a result of these aforementioned problems, during oil production in production wells, the drilling of new wells, or workovers of existing wells, many chemicals, referred herein as “additives”, which include scale inhibitors, are often injected from a surface source into the wells to treat the formation fluids flowing through such wells to prevent or control the precipitation mineral scale. In addition to controlling mineral scale precipitations, additives are also injected into producing wells to, among other things, enhance production through the wellbore, lubricate downhole equipment, or to control corrosion, and the formation or precipitation of asphaltenes, paraffins, emulsions and hydrates.
All of these chemicals or additives are usually injected through a conduit or tubing that is run from the surface to a known depth within the formation. Surface (topside) pipelines and equipment may also be protected by continuous injection or batch treatment of additives directly into the system, typically upstream of the problem location. In addition, an additive can be injected into a near wellbore formation via a technique commonly referred to as “squeeze” treatment, from which the additive can be slowly released into the formation fluid. Also, chemicals are introduced in connection with electrical submersible pumps, as shown for example in U.S. Pat. No. 4,582,131, or through an auxiliary line associated with a cable used with the electrical submersible pump, such as shown in U.S. Pat. No. 5,528,824.
In order to effectively inject additives into a formation fluid in order to control scaling, it is necessary to know how much of the additives are needed. At present, scaling tendency and scale occurrence are typically assessed by using an in-situ scale coupon or relying on water samples derived from production or injection sources. Off line field water samples are typically analyzed for ion concentrations either in the field or these samples are sent to an off-site laboratory wherein instrumental analysis is utilized to determine the relative concentrations of scaling ions contained in a given water sample. Again, another off-line approach to predicting and monitoring scale tendency and occurrence is the use of coupons which require their removal from the well system for inspection either in the field or at an off-site facility. Stated simply, there is a need for a real-time and in-situ monitoring technique for detecting the on-set of scale deposition in a production or injection system, where high pressure, turbulence and/or multiphase fluids may exist.